Most of the energy used in the world is derived from the combustion of carbon and hydrogen-containing fuels such as coal, oil and natural gas. In addition to carbon and hydrogen, these fuels contain oxygen, moisture and undesirable contaminants such as SOX, e.g., SO2, SO3 and the like, NOX, mercury, chlorine, and other trace elements. Awareness regarding the damaging effects of the contaminants released during combustion triggers the enforcement of ever more stringent limits on emissions from power plants, refineries and other industrial processes. There is an increased pressure on operators of such plants to achieve near zero emission of contaminants.
It has been shown that ammonia, as well as amine solutions, efficiently removes CO2, as well as other contaminants, such as sulfur dioxide (SO2) and hydrogen chloride (HCl), from a flue gas stream. In one particular application, CO2 is absorbed in an ammoniated solution at temperatures lower than the exit temperature from a flue gas desulfurization system. The SOx contaminants, e.g., SO2, SO3, remaining in the flue gas coming from the wet flue gas desulfurization (WFGD) and/or dry flue gas desulfurization (DFGD) is often captured by ammonia to produce an ammonium sulfate bleed stream. Ammonium sulfate is also produced in the ammonia reduction stages of the carbon capture from the exhaust flue gas. For instance, a current solution to capture ammonia exiting from the absorber of a carbon capture system is a two-step process. In the first step, the ammonia is captured in a water wash system and in the second step the residual ammonia is captured in the column of a Direct Contact Heater (DCH) by using sulfuric acid. The captured residual ammonia with sulfuric acid produces ammonium sulfate salt.
Ammonium sulfate can be used as a commercial fertilizer, but processing of the ammonium sulfate byproduct can be energy and capital cost intensive. In addition, a large area for silos\bins for indoor storage of the ammonium sulfate byproduct may be needed on-site to insure plant availability. In addition, trace metals may be present in the ammonium sulfate stream that may require further treatment or disposal of the ammonium sulfate stream as a hazardous waste. The result is higher operating costs and capital costs because of the larger equipment needed to account for sulfur and the higher reagent make-up rates. Unfortunately, it has been found that the ammonium sulfate by-product does not offer much value to the customers. It has become more of a liability to the customers.
FIG. 1 illustrates such a known system 10 for removing contaminants from a flue gas produced by combustion of a fuel, such as coal, oil or natural gas in a boiler of a plant, such as a power plant, which produces ammonium sulfate. The system 10 includes a Direct Contact Cooler (DCC) 12, a carbon dioxide (CO2) removal system 14, a water wash system 16 and a Direct Contact Heater (DCH) 18. The flue gas may be treated prior to being provided to the DCC 12 by a desulfurization system (known as wet flue gas desulfurization systems (“WFGD”) and dry flue gas desulfurization systems (“DFGD”)), particulate filters (including, for example, bag houses, particulate collectors, and the like), as well as the use of one or more sorbents that absorb contaminants from the flue gas. Examples of sorbents include, but are not limited to, activated carbon, ammonia, limestone, sodium bicarbonate, Trona, and the like.
The DCC 12 of the system 10 in FIG. 1 receives a gas stream, such as flue gas, via a gas inlet 20 at the bottom of a gas-liquid contacting device 26. The gas-liquid contacting device, also referred to as the sulfur removal device 26, is configured to remove SO2 from the flue gas. In the sulfur removal device 26, flue gas is forwarded upwards and contacted with a liquid comprising ammonia having a pH-value of approximately 4-6 at flue gas saturation temperature. The liquid is supplied via pipe 30 and distributed over the sulfur removal device by a set of nozzles 32 or pipes with holes for liquid distribution. The sulfur removal device 26 contains a structured packing, or another suitable gas-liquid contacting filling.
SO2, and optionally other acidic gases such as HCl, HF, SO3, is removed from the flue gas by formation of ammonium sulfate upon contact with the ammonia comprised in the liquid. The used liquid, containing ammonium sulfate, is collected in a liquid collection receptacle at the bottom of the sulfur removal device. Dissolved ammonium sulfate is removed by a bleed stream 34. The remaining liquid is, via pipe 30, directed for reuse in the sulfur removal device 26. Ammonia make-up is required in this section for the capture of the incoming acidic gases.
The flue gas, depleted in SO2, leaving the sulfur removal device 26 enters another gas-liquid contacting device 28 via the liquid collection receptacle 36. The gas-liquid contacting device 28, containing a structured packing, or another suitable gas-liquid contacting filling, is also referred to as the gas cooling device 28. In the gas cooling device 28, the flue gas depleted in SO2, while forwarded upwards, directly contacts with a cooling liquid. The cooling liquid consisting essentially of water is supplied via pipe 38 and distributed by a set of nozzles 40, or pipes with holes for liquid distribution, over the gas cooling device. The gas cooling device 28 thus functions as a heat-exchanging device by transferring heat from the flue gas to the cooling liquid. In addition, any water in the flue gas is condensed therefrom. The stream 38 can be sent to either a cooling tower or mechanical chiller or the combination of both cooling tower and mechanical chiller before returning it back to the gas cooling device 28.
The thus heated liquid formed in the gas cooling device 28 is collected in the liquid collection receptacle 36, withdrawn via pipe 42 and forwarded for use in the DCH 18 as described below. The DCC 12 of FIG. 1 thus provides a cool and SO2 depleted flue gas for supply via duct 44 to the carbon dioxide removal system 14.
The flue gas then leaves the DCC 12 via a duct 44 to the carbon dioxide removal system 14. The flue gas in the duct 44 has a temperature of about 0-40° C., specifically 0-5° C. As mentioned previously, the type of carbon dioxide removal system 14 described herein is sometimes referred to as the chilled ammonia process (CAP).
The carbon dioxide removal system 14 comprises a CO2 absorber 46 in which the flue gas is brought into contact with an ammoniated slurry or solution. A pipe 47 is configured to forward, by means of a high pressure pump (not shown), a CO2 enriched slurry or solution from the CO2 absorber 46 to a regenerator 48. Heat is provided to the regenerator 48 by heating stream 50 in (reboiler) 52. The high pressure and high temperature in the regenerator 48 causes the release of high-pressure gaseous CO2, stream 54. A pipe 56 is configured to return CO2-lean ammoniated solution or slurry from the regenerator 48 to the CO2 absorber 46. Heat exchangers 58 can be disposed between the absorber 46 and the regenerator 48 to control the temperature of the streams in pipes 47 and 56 circulating between the two components. There might be more heat exchangers configured between absorber 46 and regenerator 48 to provide heating or cooling requirements of the process as needed.
A duct 64 is configured to forward the flue gas, now having a low concentration of carbon dioxide, from the CO2 absorber 46 to a water wash vessel 60 of the water wash system 16, which is operative for removing ammonia, NH3, from the flue gas that has been treated in the CO2 absorber. A stream of cold water or cold and slightly acidic solution is cooled in a heat exchanger 62 and is supplied to the water wash vessel 60. A duct 74 is configured to forward the flue gas, which has been cleaned in the water wash vessel 60, to the DCH 18 for further removal of the ammonia from the flue gas by means of sulfuric acid.
An ammonia stripper 66 can be disposed in fluid communication with the water wash vessel 60. The ammonia stripper 66 is configured to recover the ammonia captured from the flue gas in the water wash vessel 60. In the ammonia stripper 66, water stream, now containing the ammonia removed from the flue gas, can be heated at a temperature by a (reboiler) 67 which boils off the contaminants to form a stripper off gas stream 68 comprising ammonia, CO2 and water while the remaining liquid phase can continue back through the water wash vessel 60. The stripper off gas stream 68 may be provided back to the absorber 46 to recovery the ammonia and some CO2 and water. Similar to the absorber 46 and regenerator 48 pair, heat exchangers 62 can be disposed between the water wash vessel 60 and the ammonia stripper 66 to control the temperatures of the streams circulating between the two components. There might be more heat exchangers configured between the water wash vessel 60 and stripper 66 to provide heating or cooling requirements of the process as needed.
The DCH 18 thus receives CO2 depleted flue gas and an ammonia content of, for example, 200 ppm, from the water wash system 16. The DCH comprises at least a first gas-liquid contacting device 72, also referred to as the ammonia removal device, which is arranged to receive the flue gas supplied via duct 74. The ammonia removal device 72 is arranged to, at least partly; remove ammonia from the flue gas by bringing the flue gas into direct contact with acidic liquid comprising ammonium sulfate. The acidic liquid is supplied via pipe 76 and distributed over the ammonia removal device 72 by a set of nozzles 77, or by pipes with holes for liquid distribution. The flue gas enters at the bottom of the device 72 and is forwarded upwards through the device. In the ammonia removal device 72, which contains a structured packing or another suitable gas-liquid contacting filling, the flue gas is contacted with the liquid having a low temperature. Ammonium sulfate is formed in the liquid and removed by bleed stream 78. The remaining acidic liquid is, via pipe 76, directed for reuse in the ammonia removal device 72. Make-up liquid is required in this section for the capture of the incoming acidic gases.
The flue gas depleted in ammonia is forwarded from the ammonia removal device 72 to a second gas-liquid contacting device 80 of the DCH 18. The second gas-liquid contacting device 80 is also referred to as the gas heating device. The flue gas passes through the liquid collection receptacle 82, in which the liquid used in the gas heating device 80 is collected. The gas heating device 80, containing a structured packing or another suitable gas-liquid contacting filling, is arranged to bring the flue gas, having essentially the same temperature as when entering the ammonia removal device, into direct contact with a heating liquid. The heating liquid, supplied via pipe 42 and distributed over the device 80 by a set of nozzles 84 or by pipes with holes for liquid distribution, is essentially the same liquid as used for cooling in the gas cooling device 28 of the DCC 12. When the liquid is contacted with the flue gas in the gas heating device 80, heat is transferred from the liquid to the flue gas. The cleaned and heated flue gas, having a temperature of, e.g. 40-60° C., leaves the gas heating device via duct 70 and is released to a stack (not shown). The used liquid, having a lower temperature after passing the device 80 as compared to before entering the device, is collected in the liquid collection receptacle 82, withdrawn via pipe 38 and directed for use in the gas cooling device 28 of the DCC 12, optionally via a process cooling tower (not shown). The DCC 18 thus provides post-cleaning of the flue gas by removal of ammonia and heating of the flue gas, before releasing a cleaned and heated flue gas to stack.
A similar known system for removing contaminants from a flue gas produced by combustion of fuel in a boiler of a power plant is described in US patent publication no. US 2013/0175004 A1, which is incorporated by reference in its entirety.
Accordingly, there is a need in the art for improved systems and processes to eliminate or significantly reduce the production of the ammonium sulfate byproduct and recovering the ammonia in carbon capture systems.